Apparatus and Methods for Natural Gas Transportation and Processing

ABSTRACT

In the transportation and processing of natural gas liquid nitrogen and liquid carbon dioxide is used in a heat exchanger process to liquefy natural gas supplied by a field site. The liquefied natural gas is transported to a regasification plant where cold energy in a part of the liquefied natural gas in an air separation device is used to produce liquid nitrogen and oxygen, natural gas. The oxygen is combusted in a power production plant, which captures the carbon dioxide produced by the combustion. This carbon dioxide is liquefied it using another part of the liquefied natural gas. The liquid nitrogen and liquid carbon dioxide is then transported to be used for further liquefaction of natural gas supplied by the field site.

The present invention relates to the transportation and processing of natural gas, in particular stranded natural gas.

On a relative basis, natural gas is the fastest growing energy resource in the world. To transport large quantities of natural gas over long distances, it is advantageous to produce Liquefied Natural Gas (LNG). LNG production has increased by 7% per year for the last two decades. LNG is mainly used in gas power plants for energy production. Gas that cannot be transported economically by pipeline or large scale LNG facilities is referred to as stranded natural gas. Stranded natural gas can arise due to the inaccessible nature of the source of gas, and also through the remoteness of the source from its market. Several concepts exist for the utilization of stranded natural gas, among these are: re-injection into an oil reservoir or well for Enhanced Oil Recovery (EOR); Gas to Liquid (GTL); Gas to Hydrates (GTH) and Gas to Wire (GTW). Transport of natural gas to the market or processing site in semi-pressurized vessels, as pressurized LNG, can also be utilised to allow exploitation of minor stranded gas fields. At the end of 2004 a total of 412 billion cubic metres of natural gas, or the equivalent of the Ormen Lange Gas field, had been injected in the North Sea for EOR.

Improved processes for the transportation and processing of natural gas to enable the full utilisation of the energy stored in the hydrocarbons in the natural gas would be highly desirable. In addition, a process that enabled natural gas injected for EOR to be recovered would also clearly be beneficial. One candidate that has been considered as an alternative gas for EOR use is CO₂. The use of CO₂ for EOR has the added advantage that it enables CO₂ that has been produced from the combustion of fossil fuels to be safely stored in the ground instead of being released into the atmosphere where it would act as a greenhouse gas.

The endeavour to reduce global CO₂ emissions was formalized in the Kyoto agreement. The combustion of fossil fuels is a main contributor to the increasing amount of CO₂ in the atmosphere, and thereby to the greenhouse effect. Although alternative energy sources are being developed, fossil fuelled power plants with CO₂ sequestration seem to be the only practicable way to meet increasing energy demands in the next decades whilst still fulfilling the Kyoto agreement.

Thus, once captured as a product of hydrocarbon combustion, to avoid undesirable emission to the atmosphere, CO₂ may be transported and injected into a final storage location. Several formations in the North Sea are suitable for a final CO₂ storage. The best known storage is probably the Utsira formation, where 8 million tonnes of CO₂ have been injected from the Sleipner field in the period from 1996 to 2004. Utilizing CO₂ for Enhanced EOR adds value to the CO₂ due to the resultant increase in oil production. In addition the natural gas that was previously injected for EOR can be exploited as it is replaced by CO₂. Among the long-term storage options of CO₂, EOR is the solution that can introduce an infrastructure for CO₂ handling on a financially sound basis. In fact Statoil and Shell are planning to capture CO₂ from an 860 MW Power Plant at Tjeldbergodden in Norway. 2.5 Million Tonnes of CO₂ are to be transported in a pipeline to the North Sea fields Draugen and Heidrun at Haltenbanken and used for EOR. However, it is claimed that even with the current oil price ($70 US/barrel), the use of CO₂ in this way would still require additional funding.

WO 03/066423, which relates to liquid petroleum gas (LPG) rather than natural gas, addresses the problem of reducing CO₂ emissions to atmosphere, and discloses the use of CO₂ for EOR. Liquid CO₂ (LCO₂) is transported to an offshore site on a suitable vessel, and is used, at least in part, to provide cooling in a heat exchanger of a separation unit. The separation unit receives a flow of wet gas and condensate and separates this into LPG, dry gas, and condensate. The LPG and condensate are stored on the vessel and transported to an onshore site, whereas the dry gas is passed back to the oil platform for subsequent further transport.

In a preferred embodiment of WO 03/066423, the CO₂ used to produce LCO₂ is a product of the combustion of hydrocarbons.

For natural gas, two conventional transport chains are known, namely pipeline and ship transport. It is of course possible to include elements from both pipeline and, ship transport in the same chain. In state-of-the-art pipeline transport, the natural gas is conditioned to dew point specifications and compressed before it is transported onshore in a pipeline, e.g. to a power plant. As noted above, gas power plants may be provided with CO₂ capture in order to avoid CO₂ emissions. Three main concepts for suitable onshore cycles are described in the literature: pre-combustion, post-combustion and Oxyfuel. A comparison of different cycles can be found in Kvamsdal et al, 2004, “Benchmarking of gas-turbine cycles with CO₂ capture”, proceedings, 7^(th) International Conference on Greenhouse Gas Control Technologies (GHGT-7), Vancouver.

The captured CO₂ may then be conditioned to transport specifications, compressed and transported offshore where it is injected in an oil reservoir for EOR. The CO₂ may be transported by pipeline or ship.

The main disadvantage with pipeline transport, both for CO₂ and natural gas, is the large investment costs and lack of flexibility, and this is particularly significant for stranded natural gas. Ship transport of CO₂ is the most flexible and economically viable solution for transporting small and medium amounts of CO₂ to the North Sea for EOR. Large-scale ship-based transport of CO₂ is relatively new, and the most important work was presented at the 7^(th) international conference on greenhouse gas technologies in Vancouver, 2004. A compilation of this material with analyses of costs, energy use, exergy efficiency and CO₂ emissions can be found in “Ship transport of CO₂—Technical solutions and analysis of costs, energy utilization, exergy efficiency and CO₂ emissions”, by Aspelund et al., 2006, Chemical Engineering Research and Design, Official journal of the European Federation of Chemical Engineering: Part A, Special Issue—Carbon Dioxide: capture, storage and utilization.

Where ship transport is employed, natural gas is liquefied and stored at the field site. Offshore this is referred to as a Floating Production, Storage and Offloading vessel (FPSO). Then it is unloaded to an LNG carrier, which transports the LNG onshore to the receiving terminal. At the receiving terminal the LNG is pumped to storage tanks, vaporized and sent to a power plant. Where this has CO₂ capture facilities, the CO₂ may then be liquefied, stored and sent to a CO₂ ship, which transports the LCO₂ to a injection well. At the offshore site, an offshore unloading system including pumping, heating and transport of CO₂ to the injection well is required; however, no storage is needed offshore as batch injection actually is favourable for the oil recovery.

The gas specifications for ship transport are stricter than for pipeline transport both for natural gas and CO₂. A further drawback with the prior art is the lack of integration of CO₂ and LNG transportation.

FIG. 1 shows a complete chain for electricity generation with CO₂ capture based on natural gas. The main areas in this chain are; (1) production and transport of natural gas, (2) gas to electricity with CO₂ capture and (3) transport and injection of CO₂. The problem with conventional standard processes is that there is a lack of integration between the separate parts of the chain. It would therefore be advantageous to create an integrated energy and cost effective transport chain, in particular for stranded natural gas, for power production with CO₂ capture where the CO₂ is used for EOR.

In the pipeline chain there are few integration possibilities. Although the ship transport chain is rather complex there are several possibilities for improvements and integration. LNG production is energy demanding and cost intensive, and it would therefore be beneficial to facilitate LNG production in combination with chain integration.

WO 96/17766 discloses one prior art method of obtaining LNG offshore in which a conversion plant is provided on a tanker to produce LNG from natural gas. Natural gas, which is largely methane, cannot be liquefied by just increasing the pressure as with heavier hydrocarbons used for energy purposes. To liquefy natural gas it is necessary to greatly reduce the temperature. As will be appreciated, this involves significant energy input at the source of natural gas, and can also result in large and complex equipment being required at the source, which, as in WO 96/17766, is often offshore and in particular with stranded natural gas the source is, by its nature, not easily accessible.

The cryogenic exergy in LNG is roughly 1.5% of the chemical potential and it would be advantageous to utilize this exergy. To make use of this ‘cold energy’ a cold carrier between the production and receiving terminals can be used to reduce the overall losses by effectively recycling the energy investment made when liquefying the natural gas. Two main cold carriers have been proposed, nitrogen and CO₂.

U.S. Pat. No. 3,400,547 discloses a process for liquefaction and transportation of natural gas in which Liquid Inert Nitrogen (LIN) or liquefied air is used as a cold carrier. LIN or liquid air is transported to the field site (the source of natural gas) by cryogenic tanker ship, and used to cool and liquefy the natural gas to produce LNG. This reduces the equipment required at the field site. The gaseous nitrogen or air produced can simply be vented to atmosphere. The LNG is then pumped into the same cryogenic tanker ship and transported to an onshore site, where regasification of the LNG is used to liquefy air or nitrogen, which is then shipped to the field site. Thus, the ‘cold energy’ stored in the LNG and liquefied air or LIN is constantly recycled to reduce energy usage. Some form of energy input is required at the onshore site, to ensure that sufficient heat energy can be removed from the natural gas at the field site, and thereby avoid the need for any energy input offshore.

U.S. Pat. No. 3,400,547 also teaches that when LIN is used as the cold carrier, oxygen is advantageously produced as a by-product of the separation of air to form LIN.

This LNG/LIN concept, with LIN transport one way and LNG transport the other way, takes advantage of the fact that LIN has a lower boiling point than LNG. Hence, in an offshore process, the LNG can be liquefied by vaporization of the nitrogen. LNG is transported in the same carrier to the LNG receiving terminal. The main challenges are the costs and efficiency related to LIN production as well as the change of cargo from LIN to LNG and vice versa. U.S. Pat. No. 3,400,547 does not provide any teaching regarding the use of carbon dioxide as a cold carrier, and does not consider EOR.

JP 08269469 discloses the use of CO₂ in the form of dry ice as a cold carrier. CO₂ is separated from a combustion exhaust gas and recovered as dry ice by utilising cold stored as LNG liquefaction energy. The dry ice is then transported to a LNG production centre, where natural gas is liquefied using the cold generated by the sublimation of dry ice. The CO₂ gas formed in this step is used in a methane synthesis unit to produce methane, which is then preferably mixed with natural gas.

In this LNG/CO₂ concept with CO₂ transport one way and LNG transport the other way, an external cooling circuit for the low temperature step must be applied to produce LNG, leading to an undesirable requirement for power input at the natural gas site. In addition, the carbon dioxide is transported in the solid phase as dry ice. Dry ice is not as easy to handle and transport as the liquid phase, and heat transfer from fluid to solid (i.e. in the use of dry ice) is not as effective as transfer from fluid to fluid.

A combination of CO₂ and LIN for peakshaving LNG plants is suggested in DE 2014776, which discloses a natural gas liquefaction process in which LCO₂ and also optionally LIN are used as cold carriers. Natural gas is piped to a shipping site, where LIN and LCO₂ are used to liquefy the gas for transportation to a consumer site in the form of LNG. At the consumer site the LNG is regasified and used to liquefy CO₂ and Nitrogen, which is then transported to the shipping site.

This combined process utilising mainly CO₂, but also LIN, for liquefaction of natural gas claims to be more energy effective than the LNG/LIN process. However, the CO₂ is emitted to the atmosphere at low or ambient pressure. Furthermore, the source of the large amounts of CO₂ needed is not described, which probably is the reason that it was not further developed. The impact on the greenhouse effect by emitting CO₂ is not mentioned, as there was little focus on global warming at the time of the patent in 1971. This document also does not contemplate the use of such cold carriers for stranded natural gas, i.e. natural gas which it is not feasible or economic to access by pipeline, and the need to liquefy natural gas at the source for easier transport is not considered.

US 2003/089125 discloses a natural gas liquefaction process for use offshore where a carbon dioxide pre-cooling circuit is provided in a cascade arrangement with a main cooling circuit. The refrigerant in the main cooling circuit can be nitrogen based. However, this document does not consider shore to ship transport of LIN and LCO₂, instead the refrigerants are used in a closed refrigeration cycle. EOR using CO₂ is also not contemplated.

The inventors have developed an energy- and cost-effective transport chain for natural gas, in particular for stranded natural gas, utilized for power production with CO₂ capture and storage. It includes a remote or offshore section for LNG production, a combined gas carrier, and a market or onshore section.

Viewed from a first aspect the present invention provides a method of liquefaction of natural gas supplied by a field site, the method comprising the steps of: providing supplies of liquid nitrogen and liquid carbon dioxide, performing a heat exchange process between the liquid nitrogen and the liquid carbon dioxide and the natural gas to thereby liquefy the natural gas, wherein the heat exchange process is arranged so that the resultant carbon dioxide is in gaseous or supercritical form at a pressure suited for enhanced oil recovery.

The “field site” is the location of the remote LNG production section which may be offshore or seaside onshore. Preferably the gas is indeed injected into ground formations as part of an enhanced oil recovery process. However, the gas may be injected into any suitable formation, or indeed into deep sea, for sequestration. The quantities, or at least the relative proportions, of natural gas and carbon-dioxide are preferably pre-determined.

The natural gas can be transported in an onshore (or offshore) pipeline from the reservoir to the production site or market site where it is liquefied. Similarly the CO₂ can be transported in an onshore (or offshore) pipeline to the reservoir.

The market site is generally onshore, however, it may be placed offshore to take account of safety or space requirements near the market. The phrase market site includes both possibilities.

References to CO₂, nitrogen and oxygen, in both gaseous and corresponding liquid forms, should generally be taken to mean a substance containing those gases to such extent that the disturbing influence of other components is avoided. It will of course be appreciated that depending upon the specific circumstances varying degrees of purity and/or contamination can be allowed without detrimental effect.

In addition, whilst nitrogen is the preferred ‘cold carrier’, because of its abundance and lack of adverse environmental impact, the invention is not limited only to the use of nitrogen. Instead, it is only necessary that the cold carrier used in conjunction with LCO₂ to liquefy the natural gas is a substance having a boiling point lower than that of LNG that can be utilised in a heat exchange process in the same way as LIN.

Viewed from a second aspect, the present invention provides an apparatus for liquefaction of natural gas, the apparatus being arranged to receive liquid nitrogen, liquid carbon dioxide and natural gas, wherein the apparatus comprises: a heat exchange device for transferring heat between the natural gas and the liquid nitrogen and the liquid carbon dioxide to thereby liquefy the natural gas, and wherein the heat exchange device is arranged such that the resultant carbon dioxide is in gaseous or supercritical form at a pressure suited for injection for enhanced oil recovery.

Thus, in the first and second aspects, the invention enables CO₂ ready for EOR to be produced from a natural gas liquefaction process. The natural gas of the second aspect is preferably supplied by a field site and more preferably the apparatus is arranged to receive natural gas at the field site. The CO₂ can then be used for EOR at the field site, thus leading to environmental benefits as discussed above. Cold energy stored in the LCO₂ and LIN is transferred to natural gas, but contrary to conventional heat exchange processes the CO₂ does not finish at atmospheric conditions, and instead is provided at a pressure suitable for EOR. If EOR is not required, then the CO₂ produced may be readily sequestered for final storage, for example in a suitable geological formation. The use of LCO₂ as a ‘cold carrier’ in conjunction with LIN has advantages in efficiency as discussed for example in DE 2014776.

Preferred features of the first and second aspects are discussed below and should be taken to include apparatus and method features equivalent to the method and apparatus features described as appropriate.

It will be appreciated that the method and apparatus of the first and second aspects is particularly advantageous when the field site is an offshore installation, and therefore in a preferred embodiment the liquefaction occurs offshore with the natural gas being sourced from an offshore installation.

Preferably, the heat exchange process or device is arranged to be self-sufficient with power, such that no power input is required to run the process. Thus, heat exchangers, compressors, expanders and pumps may be used, and preferably the power output of the expanders is balanced against the power input for the compressors and pumps. By avoiding the need for power input at the field site, the apparatus at the field site and in particular the heat exchanger can be made to be simple and self-sufficient.

Preferably the resultant nitrogen is substantially returned to atmospheric conditions, and vented to atmosphere, with the cold energy stored by the liquid nitrogen transferred to the natural gas during the liquefaction.

In a preferred embodiment, a combined carrier is provided, which initially contains the liquid nitrogen and the liquid carbon dioxide. In this embodiment, after heat exchange has been carried out, the liquefied natural gas is loaded onto the combined carrier. The combined carrier may be a gas transport vessel, preferably a multigas ship, particularly in the case where the field site is an offshore installation. Preferably the liquefied natural gas is stored in the same storage vessels on the combined carrier as the liquid nitrogen and the liquid carbon dioxide. This allows more efficient utilisation of the carrier, particularly in comparison to the prior art situation where the LNG and LCO₂ are transported in completely separate vessels.

In a preferred embodiment the heat exchange device is provided on the combined carrier. This avoids the problematic cryogenic transfer of LNG, LCO₂ and LIN between the combined carrier and the field site, as all transfers will be in the gaseous or supercritical phase. Further, expensive modification to the field site is not required, and instead the combined carrier may be advantageously arranged to interact with existing apparatus on current field sites.

The heat exchange process/device may include one or more heat exchangers, compressors, expanders and pumps, the arrangement of which is preferably optimised for efficiency using conventional techniques. In preferred embodiments the arrangement is such that the two phase region is avoided in at least one of and preferably all of the nitrogen, carbon dioxide and natural gas paths.

Preferably the heat exchange process does not include any additional refrigeration, and in particular does not require the use of hazardous materials such as flammable refrigerants. By using only LIN and LCO₂ to liquefy the natural gas, the need for refrigerants at the field site can be avoided, and any additional power input for the LNG/LIN and LCO₂ cycle can be carried out when producing the LIN and LCO₂ onshore. Thus, the need for power input at the field site can also be avoided. This is particularly useful when the field site is offshore, or otherwise in a remote or inaccessible location.

Viewed from a third aspect, the present invention provides a method of producing natural gas, liquefied carbon dioxide and liquefied nitrogen comprising: providing amounts of liquefied natural gas, gaseous carbon dioxide and gaseous nitrogen, and transferring heat from the carbon dioxide and nitrogen to the liquefied natural gas in order to gasify the natural gas and liquefy the carbon dioxide and nitrogen.

Viewed from a fourth aspect, the present invention provides an apparatus comprising a heat exchanger, the apparatus arranged to receive liquefied natural gas, gaseous carbon dioxide and gaseous nitrogen and to produce liquid carbon dioxide and liquid nitrogen by gasification of the liquefied natural gas and transfer of heat from the carbon dioxide and nitrogen to the liquefied natural gas.

In the third and fourth aspects, LNG is used to liquefy nitrogen and carbon dioxide. The resultant LCO₂ and LIN can then be utilised as cold carriers, and can be transported to a source of natural gas and used to liquefy the natural gas. A continuous process can thus be established in which the cold energy of the liquefied gases is recycled during each stage of transport. In contrast to prior regasification processes, which generally produce only LIN, both LCO₂ and LIN are produced and these can then be used to meet the requirements of an offshore natural gas liquefaction process as described in relation to the first and second aspects above. Preferably, the process is arranged such that all of the input LNG is gasified, and all of the input gaseous CO₂ and nitrogen is liquefied.

Preferred features of the third and fourth aspects are discussed below and should be taken to include apparatus and method features equivalent to the method and apparatus features described as appropriate.

The apparatus may also include one or more further components selected from heat exchangers, compressors, expanders and valves. The function of such components is to increase the efficiency of the processing of the various liquid and gaseous materials, and to allow repeated heat exchange stages either over multiple heat exchangers or by cycling the materials several times through the same heat exchanger.

The LNG is preferably initially at atmospheric pressure and is compressed, preferably by pumping, prior to regasification to avoid compression in the gas phase after heat exchange. The CO₂ and nitrogen may also be initially at atmospheric pressure and thus are compressed prior to being liquefied. The CO₂ is preferably compressed to a pressure higher than its triple point (5.2 bar) before it is liquefied to avoid dry-ice formation. The nitrogen is compressed to a pressure higher than the transport pressure in order to be liquefied by heat exchange with the LNG. Receiving nitrogen and/or CO₂ at higher pressures will increase the efficiency and reduce the investment costs and is therefore preferable.

In a preferred embodiment, the output natural gas is at above atmospheric pressure. This makes later handling and transport of the gas easier. The LCO₂ is transported at a pressure higher than the triple point (TP) and preferably at as low a pressure as possible above the triple point, for example 5.5 bar, to increase ship utilization. The LIN can be transported at ambient pressure, or preferably elevated pressure, for example at 6 bar, to increase the total chain efficiency. Compression and/or expansion of the various materials during the heat transfer, liquefaction and regasification process helps to improve the efficiency of this process. By retaining the output gas and/or liquid(s) at an elevated pressure the efficiency of later process steps can be improved, and in particular the efficiency of a transportation cycle in which liquefied gases are used as cold carriers between a natural gas source and a natural gas destination can be improved. Thus considerable advantages can be realised by using an elevated (above atmospheric) output pressure.

The natural gas process may comprise compression and/or pumping along with heating by heat exchange with the carbon dioxide and nitrogen.

The nitrogen process preferably includes compression followed by cooling by heat exchange with the natural gas to produce liquid nitrogen (LIN). A valve may be used to reduce the pressure of the LIN to a pressure suitable for transport. Flash gas produced at the valve is preferably recycled to the compressor and may be used in heat exchange to cool the incoming nitrogen gas and/or carbon dioxide.

Liquefaction of the carbon dioxide may be achieved by compression followed by heat exchange with the natural gas. After compression the carbon dioxide may be cooled by ambient air or water coolers to ambient temperatures. Preferably the compression is a multi-stage compression process, and in a preferred embodiment the carbon dioxide is split into two streams after a compression stage is complete, with one stream being cooled by heat exchange with the natural gas, and the other stream being compressed further before cooling to achieve a better utilization of the LNG cold and thereby a higher efficiency.

Preferably an air separation unit (ASU) produces the nitrogen to be liquefied. The ASU may be powered from an external source.

The ASU will also produce oxygen, which may be used for an Oxyfuel Power Plant, where oxygen along with natural gas, which is preferably sourced from the regasified natural gas, is converted to electricity, CO₂ and water. In a preferred embodiment the water is removed from the CO₂ during the compression process before the CO₂ is liquefied by the LNG. Prior to liquefaction the CO₂ is preferably compressed to a pressure above the triple point to avoid dry ice formation.

Alternatively or in addition CO₂ for liquefaction may be provided by an external industrial source such as steel and cement industry, or a coal, bio-mass or natural gas fired power plant with CO₂ capture.

The LCO₂ together with LIN is preferably transported to a field site, such as an offshore site, in a combined gas carrier. The LCO₂ may be regasified and utilised for EOR, preferably in accordance with the first and second aspects of the invention and the preferred features thereof with the LIN similarly being regasified, and then vented to atmosphere.

Viewed from a fifth aspect, the present invention provides a method of producing natural gas, liquefied carbon dioxide and liquefied nitrogen comprising the steps of: providing a (preferably predetermined) amount of liquefied natural gas, using a part of the liquefied natural gas in the separation of air to produce oxygen and liquid nitrogen by regasifying the natural gas, and combusting the oxygen and at least part of the regasified natural gas in a power production plant.

Viewed from a sixth aspect, the present invention provides an apparatus for carrying out the method of the fifth aspect, the apparatus comprising: an air separation unit which receives liquefied natural gas and air, and produces oxygen, liquid nitrogen and regasified natural gas, and a power production plant which combusts the oxygen and regasified natural gas.

In the fifth and sixth aspects, oxygen which is produced as a by-product of the transfer of cold energy from the LNG to LIN is utilised for combustion with the natural gas to thus produce power. LIN is made available for use as a cold carrier, which may be transported to a source of natural gas and used in the liquefaction of the natural gas. The cold energy stored in the LNG is therefore not wasted. By integration of the power production with the cold energy transfer process in this way, the efficiency of the process as a whole is enhanced. These aspects thus provide an alternative onshore process to that for the third and fourth aspects, although the features of the fifth and sixth aspects could also be advantageously combined with the third and fourth aspects respectively. Preferred features of the fifth and sixth aspects are discussed below and should be taken to include apparatus and method features equivalent to the method and apparatus features described as appropriate.

In a preferred embodiment, carbon dioxide produced by the combustion process is captured. Preferably the carbon dioxide is liquefied by gasification of another part of the liquefied natural gas. The regasified natural gas produced may be used in the combustion process. In a particularly preferred embodiment the power production plant is an Oxyfuel power plant, which combusts oxygen and natural gas to produce water, carbon dioxide and electricity. Carbon dioxide may be added to the oxygen prior to combustion to reduce the combustion temperature. This carbon dioxide may be sourced from the carbon dioxide emitted by combustion.

The capture of carbon dioxide is obviously beneficial in avoiding carbon dioxide emissions. Liquefaction utilising cold energy stored in the LNG provides LCO₂ as a cold carrier, and allows the CO₂ produced by the power production plant to be transported for storage elsewhere. Preferably, the LCO₂ is used for EOR. The capture and liquefaction of carbon dioxide allows the above process, which in preferred embodiments occurs at an onshore market site, to be integrated with the natural gas liquefaction process of the first and second aspects.

The use of an Oxyfuel power plant is preferred, as this type of power plant provides clean and efficient power production from natural gas and oxygen. The end result of a process including the Oxyfuel plant is electricity, water, LCO₂ and LIN. The latter two products may be used as a cold carrier, with the LCO₂ preferably being regasified and utilised for EOR, preferably in accordance with the first and second aspects of the invention and the preferred features thereof and the LIN similarly being regasified, and then vented to atmosphere.

The regasification of LNG in an efficient integrated process results in more natural gas than can be combusted using the oxygen which is produced. Therefore, in a further preferred embodiment, an additional power production plant is provided for the combustion of the excess regasified natural gas. This may be any power plant, preferably one with CO₂ capture.

Viewed from a seventh aspect, the present invention provides a method for transportation and processing of natural gas, the method comprising the steps of: using liquid nitrogen and liquid carbon dioxide in a heat exchange process to liquefy natural gas supplied by a field site, transporting the liquefied natural gas to a regasification plant, utilising at least a part of the liquefied natural gas in a heat exchange process to produce liquid nitrogen and liquid carbon dioxide, and transporting the liquid nitrogen and liquid carbon dioxide to be used for further liquefaction of natural gas supplied by the field site.

Viewed from an eighth aspect, the present invention provides an apparatus for transportation and processing of natural gas, the apparatus comprising: a heat exchange device which utilises liquid nitrogen and liquid carbon dioxide to liquefy natural gas supplied by a field site, a carrier which transports the liquefied natural gas to a regasification plant, the regasification plant comprising a regasification apparatus that utilises at least a part of the liquefied natural gas in a heat exchange process to produce liquid nitrogen and liquid carbon dioxide, and a carrier which transports the liquid nitrogen and liquid carbon dioxide to be used by the heat exchange device for further liquefaction of natural gas supplied by the field site.

The seventh and eighth aspects provide a method and apparatus in which an efficient energy chain is provided, where LIN and LCO₂ are used as cold carriers to recycle cold energy stored in LNG. Preferred features of the seventh and eighth aspects are discussed below and should be taken to include apparatus and method features equivalent to the method and apparatus features described as appropriate.

Preferred embodiments of the seventh and eighth aspects can incorporate some or all of the features and preferred features of the first to sixth aspects discussed above. In particular, the field site may be an offshore installation, and the regasification and optionally power production may occur at a market site, preferably an onshore or seaside offshore market site. The liquid carbon dioxide used as a cold carrier may be output from the heat exchange device at a pressure suitable for EOR, and/or heat exchange between the liquid carbon dioxide and liquid nitrogen and the natural gas may occur as discussed above. The transportation of liquefied natural gas and the liquid carbon dioxide and liquid nitrogen may occur in a combined carrier as discussed above. The regasification site may be an onshore site and may include an Oxyfuel power plant as the power production plant.

The seventh or eighth aspect may include the use of some of the LNG in an ASU to produce the liquid nitrogen and also oxygen. In this case the LCO₂ is preferably produced using the remainder of the LNG. When the LNG is used to produce LIN from air, the oxygen which is also produced can advantageously be used in the combustion of the regasified natural gas. Undesirable carbon dioxide emissions may be avoided by capture and liquefaction of the carbon dioxide produced by combustion.

The regasified natural gas which is combusted is preferably the gas produced by the air separation unit and/or the gas produced after liquefaction of carbon dioxide. Alternatively, it may be beneficial to use the regasified natural gas in another process, or to store it for later use in another process. In this case the natural gas for combustion may be obtained from this storage, or may be from another source. The CO₂ may be obtained from the other process, or from an alternative source

In the cycle of the seventh and eighth aspects and the preferred embodiments thereof, the liquid nitrogen and liquid carbon dioxide produced by regasification of the liquefied natural gas will not be sufficient to then liquefy a corresponding amount of natural gas supplied from the field site in a subsequent cycle. Therefore, in a preferred embodiment, additional liquefied natural gas is supplied to the regasification site (market site) from a different source. The market site may be situated at or adjacent a liquefied natural gas processing plant for this purpose. This will reduce the required power input to complete the liquefaction of sufficient nitrogen and carbon dioxide. Electricity produced by the power production plant may be utilised as the additional power.

Further, similarly to the situation discussed above for the fifth and sixth aspects, the cycle will not produce sufficient oxygen from the separation of air to combust all of the regasified natural gas in the preferred Oxyfuel power plant. Therefore, in a preferred embodiment a further power plant, preferably with CO₂ capture, for example a post combustion or pre combustion power plant, is provided. The regasified natural gas may be split between the Oxyfuel plant and the other power plant in a ratio of, for example, 25% to 75%. Carbon dioxide produced by the other power plant is preferably captured and liquefied as discussed above. Preferably substantially all carbon dioxide produced by combustion of the natural gas is captured for use for EOR.

Intermediate storage may be provided between the processes and carrier at both the field site and market site and is the preferred solution at the market site. The use of intermediate storage allows continual operation of the offshore, onshore and transport parts of the cycle without the need for one part of the cycle to be delayed by down-time or differences in production or usage rates in another part of the cycle.

Preferred embodiments of the present invention will now be described by way of example only and with reference to the accompanying drawings in which:

FIG. 1 shows an example of a complete chain from natural gas well to CO₂ storage;

FIG. 2 shows schematically a simplified natural gas transport chain and the full processing chain in accordance with an embodiment of the present invention;

FIG. 3 shows schematically a more detailed natural gas transport and processing chain in accordance with an embodiment of the present invention;

FIG. 4 shows the required amount of LIN and LCO₂, the thermo-mechanical exergy content in the streams and the exergy conversion efficiency for the field site LNG process;

FIG. 5 is a process flow diagram for an offshore LNG process;

FIG. 6 is a pressure-enthalpy diagram for the natural gas path in the offshore process of FIG. 5;

FIG. 7 is a pressure-enthalpy diagram for the CO₂ path in the offshore process of FIG. 5;

FIG. 8 is a pressure-enthalpy diagram for the nitrogen path (logarithmic pressure) in the offshore process of FIG. 5;

FIG. 9 shows composite curves for the heat exchangers HX-101 and HX-102 of FIG. 5 for atmospheric LNG;

FIG. 10 shows composite curves for the heat exchangers HX-101 and HX-102 of FIG. 5 for pressurized LNG;

FIG. 11 shows the amount of LNG, LIN and LCO₂, the thermo-mechanical exergy content in the streams and the exergy conversion efficiency for the market site LNG regasification process;

FIG. 12 is a schematic process flow diagram for the onshore market site LNG regasification process;

FIG. 13 is a pressure-enthalpy diagram for the natural gas process path in the onshore process of FIG. 12;

FIG. 14 is a pressure-enthalpy diagram for the nitrogen process path in the onshore process of FIG. 12;

FIG. 15 is a pressure-enthalpy diagram for the carbon dioxide process path in the onshore process of FIG. 12;

FIG. 16 shows composite curves for the main exchangers in the onshore process of FIG. 12; for atmospheric transport pressure of LNG and

FIG. 17 shows composite curves for the main cold end heat exchanger of FIG. 12 when LNG at an increased pressure is used;

FIG. 18 shows, for the embodiment of FIGS. 2, 4 and 12, the ship utilisation and required LCO₂ and LIN versus ship- and LNG pressure;

FIG. 19 shows for the embodiment of FIGS. 2, 4 and 12, the exergy efficiency versus ship- and LNG pressure;

FIG. 20 shows the exergy efficiency for the simple transport chain showed in the inner part of FIG. 2; and

FIG. 21 shows the exergy efficiency for the total transport chain shown in the part FIG. 2 and FIG. 3;

A transport chain following interactions as shown in FIG. 1 is implemented in an improved integrated form as shown in FIG. 2. In the simplest form, only the transport of LNG and LCO₂ are considered. This simple transport chain is shown in the inner part of FIG. 2 and includes a field site section, a combined gas carrier and an integrated receiving terminal or market site. At the field site, natural gas is liquefied to LNG by Liquid Carbon Dioxide (LCO₂) and Liquid Inert Nitrogen (LIN), which are used as cold carriers. The nitrogen is emitted to the atmosphere at ambient conditions. The CO₂ at high pressure is transferred to an offshore oilfield for Enhanced Oil Recovery (EOR). The liquefaction of natural gas in an embodiment of the invention is described in detail below. The LNG is transported to the receiving terminal or market site (generally onshore) in the a combined carrier, which is described in further detail below. At the receiving terminal, the cryogenic exergy in LNG is recovered by liquefaction of CO₂ and nitrogen, which can be provided by external sources. An embodiment of the onshore process is also provided in detail below. An expanded embodiment where the process also provides both the nitrogen and CO₂ itself will be discussed. Using the same combined carrier the LCO₂ and LIN are transported to the field site, for the use of liquefaction of the natural gas. The cold carriers are the foundation in an integrated transport chain for stranded natural gas utilized for power production with CO₂ capture where the CO₂ is used for EOR.

In one embodiment the simple transport chain is integrated with an air separation unit (ASU) and a conventional oxyfuel arrangement that provides CO₂ and nitrogen to the transport chain. A schematic of such an energy chain is shown in FIG. 2 where the field site is an offshore installation and the market site is an onshore site. In a more complete Liquefied Energy Chain (LEC), the onshore process is connected to an air separation unit (ASU) that produces nitrogen for the offshore process and oxygen for an Oxyfuel Power Plant, where natural gas is converted to electricity, CO₂ and water. The water is removed from the CO₂ which is compressed to a pressure above the triple point and liquefied by vaporization of the remaining LNG. The LCO₂ together with LIN are transported offshore in the combined gas carrier. Still higher efficiencies may be achieved by integrating the vaporization of LNG directly with the ASU or power process. In the most preferred embodiment, the LEC is integrated with an external LNG receiving terminal providing additional cold exergy that is normally not utilized to the transport chain. Many of the advantages and features described below can be equally well applied to an onshore field site, and/or a seaside offshore market site.

The processes are designed using a new methodology for Process Synthesis (PS) extending traditional Pinch Analysis (PA) with exergy calculations. The procedure, referred to as Extended Pinch Analysis and Design (ExPAnD), shows great potential for minimizing total shaft work in sub ambient processes. This is achieved by optimizing compression and expansion work for the process streams together with the work needed to create necessary cooling utilities. The methodology and a detailed description of the development of the offshore process can be found in the work by A. Aspelund, D. O. Berstad, T. Gundersen entitled “An Extended Pinch Analysis and Design Procedure utilizing Pressure based Exergy for Subambient Cooling”, Applied Thermal Engineering (2007), doi 10.1016/j. applthermaleng, 2007.04.017.

The design philosophy is to create a field site process that is self-supported with power and hot and cold utilities. Hence, the required power and utilities for the energy chain is provided at the market site terminal. The processes are based on state-of-the-art equipment with standard industrial efficiencies and it is designed to have high exergy efficiency; however, efforts are made to keep the number of equipment units low. Equipment data are found in Table 1, ambient data and feed gas properties in Table 2.

TABLE 1 Equipment data Compressors Polytrophic efficiency 82% Pumps Isentropic efficiency 85% Expanders Isentropic efficiency 85% Liquid expanders Isentropic efficiency 85% Process heat exchangers MITA > 0° C. 5° C. 0 > MITA > −80° C. 3° C. MITA < −80° C. 2° C. Pressure drop 0.2 bar Ambient heat exchangers MITA 5.0° C. Pressure drop 0.3 bar Flash drums Pressure drop 0 bar Efficiency 100%  Mechanical to electrical Efficiency 98%

TABLE 2 Ambient data, feed gas conditions and composition Ambient temperature (seawater and air) 10° C. Ambient pressure 1 bar Feed gas temperature 15° C. Feed gas pressure 70 bar Feed gas composition Nitrogen 1 Mole % Methane 92 Mole % Ethane 5 Mole % Propane 1.8 Mole % n-Butane 0.1 Mole % i-Butane 0.1 Mole % Carbon dioxide 0 ppm Water 0 ppm

FIG. 3 shows a more detailed flow diagram of a LEC developed for utilization of stranded natural gas from depleting oilfields with associated gas. Associated gas 4 from an offshore oil field 6 is transferred to a combined carrier 8 via a short sub-sea pipeline, a riser and a Submerged Turret Loading (STL) anchoring system. The STL concept is described in WO 96/17766. Other conventional gas transfer systems could of course be used. The combined carrier 8 can be a multigas ship 8 as shown in FIG. 4. The combined carrier 8 transports LCO₂ and LIN on the outbound stage, and LNG on the inbound stage. To avoid offshore storage and unloading of LNG, the LNG process is placed on the combined carrier which is connected to the offshore oil field throughout the process. At the combined carrier 8, high pressure natural gas is cooled against LCO₂ before it is expanded and cooled by LIN to LNG. In an alternative embodiment, the combined carrier 8 is simply equipped to load/unload and transport the liquids, and the liquefaction of natural gas occurs at a facility provided on the offshore installation 2 (for example, an oil platform), or at another location.

The nitrogen 10 is vented to atmosphere at ambient conditions. The CO₂ at high pressure 12 is transferred to an offshore oilfield for EOR 14 through a flexible riser and a short subsea pipeline. It is advantageous that the LNG production process is arranged to have, as an end product, CO₂ at a pressure suited for EOR. This CO₂ can easily be directly injected as EOR, or stored for injection at an appropriate time, without the need for any further processing.

As shown in FIG. 4, the combined carrier transports approximately one volume of LIN to two volumes of LCO₂, with three volumes of LNG then being transported back to the receiving site. Intermediate storage 16 can be used between the carrier and the onshore site for LCO₂, LIN and LNG, and also at the offshore installation for natural gas from the well.

At the receiving terminal 18, the ship unloads the cargo to an intermediate storage and simultaneously loads a new cargo LCO₂ and LIN. In the onshore process, which can run continuously due to the intermediate storage, one part of the LNG is vaporized in an integrated Air Separation Unit (ASU) 20. The ASU 20 produces LIN for the offshore process and advantageously also oxygen. The oxygen is used in an Oxyfuel power plant 22 of a conventional type, where the natural gas is converted to electricity, CO₂ and water. As is conventional with Oxyfuel plants, some CO₂ is mixed with the oxygen prior to combustion in order to avoid excessively high temperature, which would damage the Oxyfuel plant 22 components. This input CO₂ can be sourced from the CO₂ produced by combustion. The water is removed from the CO₂ which is compressed to a pressure above the triple point (TP) and liquefied by vaporization of the remaining LNG. By utilizing the cryogenic exergy in LNG, the required power for air separation and liquefaction of nitrogen and CO₂ can be substantially reduced. The additional energy input required can be sourced, in one embodiment, from the electricity produced by the Oxyfuel plant or from the grid. Alternatively, additional LNG from another source can be utilised as a source of cold energy to further reduce the energy requirement.

The output of the onshore process is water, electricity, LCO₂ and LIN, with the LCO₂ and LIN being transported offshore by the combined carrier, where the cold energy is recovered, with the resultant nitrogen and CO₂ being vented 10 and used for EOR 14 respectively. Thus, over the cycle as a whole energy is produced from natural gas with the minimum of detrimental environmental effect, and the utilisation of natural resources is optimised. The transport chain is especially suited for tail production of oilfields with associated gas, where the gas is used for injection. CO₂ for EOR will increase the lifetime of the oilfield, thus also increase the total oil production.

As discussed above the LCO₂ and LIN are transported offshore in the combined carrier 8, which returns to shore with the LNG. Transporting CO₂ for EOR and LNG in the same ship leads to an enhanced utilization of the combined carrier over the prior art systems, and reduced complexity of the transport chain as a whole. The ship utilization is defined as the total volume of LNG, LIN and LCO₂ transported divided over two times the ship volume and thereby reflects the total capacity of the ship. The utilization rate of the combined carrier 8 can vary between 70 and 100% depending on the LNG and LIN transport pressure.

CO₂ is most preferably transported at a pressure as close to the triple point (TP) as possible. The density is higher at lower pressures and also the exergy density is higher as the temperature is lower. The LNG (and LIN) can be transported at any pressure between 1 bar and maximum ship vessel pressure. The following process description assumes a LIN pressure of 6 bar and a NG pressure of 1 bar for maximum exergy efficiency. The reason for these transport pressures is that the cold exergy in the LNG is reused at the receiving terminal; hence, although more cold duty is required offshore at low pressure, the irreversibilities are smaller, resulting in a higher efficiency for the total chain. The process design philosophy in is to minimize the LIN and CO₂ consumption with the constraint that the offshore process does not require additional power, or hot or cold utilities. Integration and utilization of the temperature and pressure exergy in LNG, LCO₂ and LIN in the LEC, will give a higher overall energy efficiency and a lower investment cost.

FIG. 5 shows one configuration, of the LNG/LCO₂-LIN offshore natural gas liquefaction process. The offshore process is self-powered and so does not need an external power source. In addition, it can operate with little rotating equipment and without flammable refrigerants. The power produced by the expanders is used to power the compressors and pumps. Another characteristic of the process is cooling of dense-phase natural gas against sub-cooled liquid CO₂ at high pressure. After heat exchange, the CO₂ is still in liquid form at ambient temperature and is pumped to injection pressure and injected for EOR. This is beneficial as no power input is required offshore to prepare the transported CO₂ for use in EOR, but instead the gas at injection pressure is produced from the liquefaction process, which is self-powered.

The cold dense-phase NG is expanded to a pressure and temperature close to the bubble point, e.g. 55 bar and −63° C. and sub cooled by high pressure LIN before it is expanded to transport pressure. The LIN is pumped to high pressure (100 bar), heated to about −40° C. and then expanded in one, preferably two, possibly several stages to utilize the pressure exergy. The hot end of the nitrogen gas can be used in addition to the liquid CO₂ in the first cooling stage. The fluids exchange heat in the dense, liquid or gaseous phase in order to avoid going through the two phase region. Therefore the heat capacity flow rate is close to constant, enabling energy exchange with small exergy losses. Since the process streams entering the heat exchangers are in single phase, mal-distribution due to two-phase flow in the manifold system is avoided.

FIG. 4 shows the inlet and outlet streams and utilities for the offshore process. The required LIN and LCO₂ flow rates are given in kg/kg LNG. The figure also shows the thermo-mechanical exergy content in the streams and the transient exergy efficiency.

The layout of suitable liquefaction systems, and the necessary heat exchangers, pumps, compressors and so on can be determined through known methods. One preferred embodiment is described here.

A process flow diagram for the offshore LNG process is shown in FIG. 5. Natural gas NG at 15° C. and 70 bar NG-1 is compressed to 100 bar, a pressure higher than the cricondenbar pressure, and cooled by liquid CO₂ and gaseous nitrogen in HX-101. The cooled natural gas in dense phase NG-3 is expanded in a dense phase expander to 50 bar, which is close to the bubble point line. It is further sub-cooled to −164° C. before it is expanded to transport pressure and stored in an LNG tank. Stream NG-6 is preferably at the bubble point to avoid purge or recycling. The NG process path is shown in a pressure-enthalpy diagram in FIG. 6.

Liquid CO₂ CO2-1 is pumped from transport pressure at e.g. 5.5 bar and Bubble Point (BP) temperature to 60 bar before it is heated in HX-101. The CO₂ pressure must be high enough to avoid vaporization. The CO₂ is then pumped to injection pressure. The CO₂ to process path is shown in a pressure-enthalpy diagram in FIG. 7. After heating and pumping, the CO₂ is transferred to an oil reservoir for EOR.

Liquid Nitrogen, N2-1 is pumped from transport pressure of, for example, 6 bar and −170° C. to 100 bar before it enters the cold-end main heat exchanger HX-102, where the dense-phase nitrogen is heated to approximately −80° C. The nitrogen is further heated to −40° C. in HX-101 before it is expanded to 10 bar in EXP-101. Then the nitrogen gas N2-5 at −160° C. is sent to HX-102 and HX-101 where it is heated to −80 and −40° C. respectively. The nitrogen gas N2-7 is compressed to 20 bar and cooled by CO₂ to −40° C. in HX-101. The gas N2-9 is then expanded to 1.4 bar in EXP-102 and sent to HX-102 and HX-101 where it is heated to −80 and 20° C. respectively. Finally, nitrogen N2-12 at atmospheric pressure and close to ambient temperature is emitted to the atmosphere. A cold vent system should be utilized to avoid accumulation of nitrogen alongside the gas carrier. The nitrogen process path is shown in a pressure-enthalpy diagram in FIG. 8.

The Composite Curves for HX-102 and HX-101 are shown in FIG. 9. The process design starts in the cold end of HX-102. The NG is to be cooled to −164° C. to avoid flashing of gas after expansion. Pumping the LIN from 6 bar to 100 bar leads to a temperature increase from −177° C. to −171° C. Since the heat capacity flow rate of the LIN is less than for the NG a temperature of −160° C. or less is required after expansion in order to obtain a pinch point at the cold end of the heat exchanger. In the current configuration the nitrogen gas is expanded from −40° C. to −160° C. in two stages. This is enough to get the cold composite curve parallel to the hot composite curve in HX-102, such that the hot-end pinch point is −77° C./−80° C. Due to the parallel composite curves in HX-102 the irreversibility losses are small, only 3.1%. The surplus power from the expansion is used to compress nitrogen at an intermediate stage.

In a thermodynamically optimal design of FIX-101, the cold pinch point should be −49° C./−52° C. which corresponds to the CO₂ inlet temperature. The reason for this is that it, from a both energy efficiency and ship utilization point of view, is desirable to use as little LIN as possible. The NG leaves the heat exchanger at −68° C. The cooling duty in the cold end of the heat exchanger is provided by cold gaseous nitrogen coming HX-102. The nitrogen streams from HX-101 are emitted at −40° C. to obtain a cold enough temperature after expansion in EXP-101 and EXP-102. Furthermore heating of nitrogen to −40° C. decreases the pinch point in HX-101 and enables the NG stream from HX-101 to have as low outlet temperature as possible, hence less cooling is required in HX-102. Increasing the nitrogen outlet temperature in HX-101 to say −30° C. will reduce the cooling duty at lower temperatures and provide cooling above the pinch temperature, where there is a surplus of cooling. The flow rate of CO₂ is tuned to avoid pinch points at higher temperatures. It is, however, important to heat the CO₂ as much as possible to utilize the cold exergy and to avoid transporting unnecessary amounts of CO₂ and thereby reducing the ship utilization. Notice the long pinch region in HX-101, giving a minor irreversibility loss of only 2.7%. Table 3 gives the irreversibility losses for the process equipment as well as the total irreversibilities. The losses are small, only 12.8%. This corresponds to 0.4% of the total (chemical and thermo-mechanical) exergy of the natural gas.

TABLE 3 Irreversibilities in the offshore process Irreversibilities Unit Description Onshore [%] K-100 NG compressor 0.57 K-101 Nitrogen compressor 1.18 P-100 CO₂ Pump 0.08 P-101 Nitrogen pump 0.38 P-102 CO₂ Pump 0.08 Mechanical-Electrical Losses 0.27 Total Consumers 2.56 EXP-101 Nitrogen HP expander 1.67 EXP-102 Nitrogen LP expander 2.05 LEXP-101 NG liquid HP expander 0.26 LEXP-102 NG liquid LP expander 0.25 Electrical-Mechanical Losses 0.28 Total Generators 4.49 HX-101 Main LCO₂ HX 2.68 HX-102 Main LIN HX 3.06 Total Exchangers & vessels 5.73 Total Irreversibilities 12.79

If the LNG transport pressure is increased, the hot stream outlet of HX-102 can also be increased. At an LNG transport pressure of 6 bar the required NG temperature before expansion is increased from −164° C. to −136° C. The required cooling duty for the NG stream is then reduced, which results in a reduction in required nitrogen. However, for state-of-the-art semi-pressurized ships with a maximum pressure of roughly 7.5 bar, nitrogen is already close to maximum pressure and it is therefore not possible to increase the temperature at the cold end of the cold Composite Curves. The Composite Curves for the heat exchangers HX-101 and HX-102 for production of semi pressurized LNG (6 bar) is shown in FIG. 10.

Since the cold end pinch is removed there are large irreversibilities, 6.5%, in HX-102 due to the large temperature difference between the cold and hot Composite Curve. These losses can be reduced by adding more expansion steps and simultaneously increase the temperature after expansion, however, this leads to increased investments.

The NG to be liquefied is at ambient temperature and a pressure of 70 bar. It is treated for water, CO₂ and heavy hydrocarbons (HHC) that would freeze out. It has a “normal” LNG composition with a dew point of −48° C. at 55 bar and contains one mole % of nitrogen. If too much HHC are present, they will have to be removed. This can be done by pre-cooling the NG to −20° C. in HX-101, expand the NG into the two phase area e.g. 50-60 bar in a compander (expander and compressor on the same shaft), which also recompresses NG. The HHC are separated from the NG in a fractionation column. The column condenser should be cooled with LCO₂. The NG is then compressed to 100 bar. The required compressor duty will not increase as the temperature of the gas to compressor K-100 will be lower than the ambient temperature, thereby reducing the shaft-work needed for compression. The exact HHC removal process depends on the feed gas composition and the LNG transport pressure. The more HHC present in the stream the more cooling in HX-101 is required. Additional cooling can be provided by increasing the amount of LCO₂.

Freeze-out of water, CO₂ or HHC will plug the narrow channels (2-3 mm) in the plate-fin heat exchangers. Hence, all water and most of the HHC and CO₂ must be removed. The freeze-out temperature of HHC and CO₂ is strongly dependent on the amount present; hence the mole fraction gives the lowest temperature for the LNG in the heat exchangers. As HHC can easily be removed in the process, the remaining discussion will focus on CO₂. Normally CO₂ will be removed by adsorption for fractions lower than 1-2 mole % and by absorption for larger fractions. Both technologies are space- and energy-demanding and should be avoided offshore if possible.

At an LNG pressure of 1 bar, almost no CO₂ can be present, giving the current LNG specification of CO₂ in LNG of 50 ppm. At 6 bar approximately 0.3 mole % can be present giving a freeze-out temperature of −140° C. At 20 bar the limit is 3.8 mole % with a temperature of −110° C. If the feed gas contains more CO₂ than the transport pressure allows, it is possible to avoid gas treatment by increasing the outlet temperature from HX-102 and allowing flash gas to form in V-101. This gas should preferably be recompressed and recycled to the feed gas. The nitrogen compressor K-101 should be removed and replaced with a flash gas compressor. Recompression will increase the power requirements; however, the required cooling duty in HX-102 and required LIN will also be reduced. It is important to notice that CO₂ may freeze out in the flash or in the gas carrier vessels.

If the cold fluid is considerably colder than the hot fluid as in HX-102 in FIG. 10, the wall temperature at the hot side may be lower than the hot fluid temperature, thus CO₂ may freeze out on the wall, plugging the channels. This can be avoided by placing an indirect cooling circuit between the cold LIN and the LNG. One solution is to use a dense-phase nitrogen circuit at 50 bar.

In the current configuration, the power generated in the expanders is equal to the power needed in the compressors and pumps. If additional power is supplied to the process, the pressure after the nitrogen compressor K-101 can be increased giving a larger cooling duty in the streams from the expanders. Hence, the outlet temperature of the nitrogen from HX-101 can be increased, thereby reducing the needed amount of CO₂ slightly or, alternatively lower the temperature after expansion giving a larger cooling duty in HX-102. Alternatively a third expander loop can be implemented in the process.

The ship's engines can be used to provide power for the nitrogen compressor. In this way the amount of nitrogen needed can be reduced, however, this will reduce the process efficiency and increase the CO₂ emissions from the ship.

The combined carrier will transport LIN and LCO₂ to the offshore installation and return with LNG to the onshore terminal, where the cargo is contained in several semi-pressurized vessels. The selected carrier size in this description is 20 000 m³. The carrier size is not particularly limited, however, typical vessel sizes might be between 10 000 and 50 000 m³. The material of the semi-pressurised vessels must be able to withstand pressures up to 7 bar and temperatures down to −175° C., hence SST 304 or 9% nickel steel or similar should be used in the vessels. The offshore process should preferably take place on the gas carrier to avoid offshore storage and loading of LNG. During the process, the combined carrier will be connected to the production facility through a flexible riser and a submerged turret loading (STL) connection. During the process, the LNG will replace the LIN and LCO₂ in the storage tanks. In order to increase the ship utilization and ease the procedures for change of grade, the combined carrier will consist of at least 6-20 semi-pressurized tanks. To avoid CO₂ emissions and maintain the efficiency of the process, it is of vital importance to develop good procedures for the change of grade between the outbound and inbound cargo. The main challenge is that LNG cannot contain much CO₂; hence the CO₂ tanks should be purged with nitrogen prior to loading of LNG. At the market site (onshore process) the LNG should be unloaded to an intermediate storage. Here, the change of grade is easier as the CO₂ may contain some natural gas without causing operational problems. The gas carrier should use electric propulsion and natural gas engines to reduce the CO₂ emissions to a minimum.

The total chain efficiency and the CO₂ emissions depend on the distance between the field and market site. It is worth noting that due to frictional pressure drop in pipelines, ship transport is more efficient than pipelines over longer distances for both natural gas and CO₂. As semi-pressurized tanks are used there is no need for a re-liquefaction unit on the gas carriers as a small pressure (and temperature) increase can be allowed for. This will, however, decrease the efficiency slightly. Any possible losses during transport (change of grade, fuel for propulsion and heat leak) are not accounted for in the results.

FIG. 12 shows one configuration of the market site process. In the onshore process, LNG at 1 bar needs to be compressed to 25 bar and vaporized. The CO₂ and nitrogen must be compressed from 1 to 5.5 and 6 bar and liquefied. In this first embodiment, the nitrogen is provided from an ASU at atmospheric pressure. The CO₂ is provided by either an external industrial source such as steel and cement industry, a coal, bio-mass or natural gas fired power plant with CO₂ capture or an integrated Oxyfuel power plant. FIG. 11 shows the inlet and outlet streams and utilities to the onshore process. The required LIN and LCO₂ flow rates are given in kg/kg LNG. FIG. 11 also shows the exergy content in the streams and the exergy conversion efficiency.

To avoid compression of natural gas in gaseous phase, the LNG is pumped to 25 bar prior to heat exchange. It is then pumped to a pressure of 75 bar, heated and expanded to 25 bar again to produce extra cooling duty and work in a direct expansion cycle. In order to be liquefied by heating of LNG, the nitrogen needs to be compressed to a pressure of 65 bar. It is then cooled, liquefied and subcooled before it is expanded to transport pressure using a valve. Additional cooling is provided by a nitrogen recycle, where some of the nitrogen is expanded from 6 to 3 bar, or alternatively 1 bar, and re-compressed to 65 bar. For a best possible utilization of the cold exergy from LNG, CO₂ is liquefied in at least three stages, at 7, 24 and 65 bar. Approximately one third of the CO₂ is liquefied at each pressure level.

The LNG is pumped to a pressure of 25 bar NG-1 before it is heated to −109° C. NG-2 by cooling of nitrogen in HX-102. To utilize the cryogenic exergy in the most efficient way, the LNG is then pumped to 74 bar NG-4 and heated to 12° C., before it is expanded to 25 bar NG-5 and re-heated to 12° C. The natural gas process path is shown in a pressure-enthalpy diagram in FIG. 13.

The nitrogen is compressed to 65 bar in four stages with intermediate cooling N2-8 before it is pre-cooled to −95° C. MN2-9 in HX-101. It is then liquefied and subcooled to −161° C. in HX-102 and expanded to the transport pressure of 6 bar N2-11 through a valve. The flash gas N2-12 is heated to −110° C. and expanded in EXP-102 to 3.2 bar, or alternatively 1 bar, N2-14 to provide additional cooling for the hot nitrogen stream. After reheating to atmospheric conditions the nitrogen is recompressed. The nitrogen process path is shown in a pressure-enthalpy diagram in FIG. 14.

The CO₂ is compressed in two stages to 7.25 bar and cooled to ambient conditions before it is split into two parts. Approximately half of the CO₂, CO₂-1, is liquefied in HX-101. The other part CO₂-4 is compressed to 24 bar and cooled to ambient conditions. It is then split in two new streams, where one stream CO2-10 is liquefied and subcooled to −55° C. in HX-101. The last part CO2-6 is compressed to 65 bar and liquefied by seawater. It is then sub cooled to −55° C. in HX-101. Due to the sub cooling there should not be any flash gas after expansion, however, a recycle stream is provided for start-up and better flexibility.

The CO₂ process path is shown in a pressure-enthalpy diagram in FIG. 15. If water and volatiles are present in the feed gas, it will be removed during the compression and liquefaction process. Most of the water will be removed in vapour-liquid separator drums after cooling and prior to expansion. To obtain the current specification of 50 ppm water, adsorption dryers should be included after the third compression stage. If more than 1% of volatiles are present a column with re-boiler and condenser should be placed after liquefaction and before the subcooling. A detailed description of gas conditioning of CO₂ for large-scale transport can be found in Aspelund, A., Jordal, K., 2007, Gas conditioning—the interface between CO₂ capture and transport, International Journal of Greenhouse Gas Control.

The Composite Curves for HX-101 and HX-102 are shown in FIG. 16. The process design starts in the cold end of HX-102. First, the LNG is pumped to 20 bar to avoid phase change through HX-102. Second, the nitrogen is compressed to 65 bar so that the condensing temperature is high enough for it to be liquefied by the heating of LNG. There is, however, not enough cooling duty at low temperature to allow the nitrogen to be subcooled enough to avoid formation of flash gas upon expansion to transport pressure at 6 bar. To avoid an external cooling unit the flash gas from MV-102 is heated to −110° C. and expanded to 3 bar and −142° C. to provide the necessary additional cooling at low temperature. A lower temperature in the sub-cooled nitrogen N2-10 gives less flash gas and thereby a smaller recycle to the nitrogen compressor train. If there are losses in the chain, the temperature in N2-10 will increase and a larger fraction of nitrogen will flash, giving a larger recycle and an increase in the energy requirements. The current design outlet temperature is −161° C. Notice the parallel Composite Curves in HX-102 resulting in small irreversibility losses of only 0.9%. If an additional 10% of LIN is needed to account for the losses in the chain, the energy requirements will increase with 11%, decreasing the exergy efficiency in the entire chain with 5%.

In HX-101, there are too large driving forces in the area between −100 and −60° C., resulting in relatively high irreversibilities (3.0%). To decrease the irreversibilities above the lowest condensing temperature of CO₂, the CO₂ is liquefied at three different pressure (temperature) levels, 7, 25 and 64 bar. The CO₂ is condensed at as low pressure as possible to reduce compressor power. The CO₂ is subcooled to −55° C. at each temperature level to avoid flash gas upon expansion.

Table 4 gives the irreversibility losses for the process equipment as well as the total irreversibilities. As can be seen from the exergy analysis, the largest irreversibilities can be found in the nitrogen and CO₂ compressor trains with aftercoolers. These compressors are also the main consumers of power. However, about 50% of these irreversibilities (13%) occur in the compression from atmospheric pressure to transport pressure of 6 and 5.5 bar and can not be avoided. Therefore, the current exergy efficiency of 71.1% is relatively high. The total losses are 28.9% in the onshore process, which means that only 1.1% of the chemical potential in the natural gas is lost in the onshore process.

TABLE 4 Irreversibilities in the onshore process Irreversibilities Unit Description Onshore [%] K-100-104 Nitrogen compressors 4.36 K-105-108 CO₂ compressors 4.22 P-101 CO₂ pump 0.17 P-102 Nitrogen pump 0.37 Mechanical-Electrical Losses 1.16 Total Consumers 10.28 EXP-101 Nitrogen HP expander 0.08 EXP-102 Nitrogen LP expander 0.90 Electrical-Mechanical Losses 0.09 Total Generators 1.07 HX-101 Main LCO₂ HX 2.98 HX-102 Main LIN HX 0.89 HE-101-108 Ambient HX 11.34 V-101 with valves Nitrogen expansion 1.86 V-102 with valves CO₂ expansion 0.48 Total Exchangers & vessels 17.56 Total Irreversibilities 28.91

An increase in LNG transport pressure will reduce the nitrogen requirements. However, the LNG temperature will also increase giving less cooling duty at low temperature for the subcooling of nitrogen in HX-102 in the onshore process. As a result, the outlet temperature of N2-10 will increase, resulting in a larger fraction of flash gas and thereby increased energy requirements due to increased re-compression. The total effect is an increase in energy requirements in the onshore section and thereby a reduction in exergy efficiency. The reason is the increase in irreversibilities in the nitrogen compressor train and in HX-102. The Composite Curves for HX-102 and HX-101 in the case of pressurized LNG at 6 bar is shown in FIG. 17. Notice the temperature gap in the cold part of the heat exchanger. The irreversibilities in HX-102 increase from 0.9% to 1.9%.

The purpose of EXP-102 is to provide additional cooling at low temperature. If the temperature difference between the transported LNG and LIN is low, and the losses throughout the chain are reduced to a minimum, the expander can be replaced with a valve. For the base-case with LNG at 1 bar and LIN at 6 bar, the duty of the expander is marginal due to the low flash rate in V-102. When losses are included or the temperature difference between LNG and LIN is increased, this expander is vital for the efficiency of the onshore process. Therefore the expander is included in all simulations.

If the nitrogen is provided by an external ASU, it should preferably be provided at intermediate pressure between 5 and 8 bars. This will decrease the total CAPEX and OPEX and increase the overall efficiency as two of the nitrogen compressors can be replaced by a marginal increase in the ASU compressors.

If the CO₂ can be provided at a higher pressure, the first part of the CO₂ compression can be avoided and hence, the exergy efficiency will be improved.

The liquid CO₂ can only contain about 0.25 mole % of volatiles. For small amounts of volatiles (<1%) it can be sufficient to use a flash drum prior to the product tank to remove to volatiles. This will, however, lead to some CO₂ emissions. In order to reduce the CO₂ losses, a column with re-boiler and condenser should be implemented in the process. The columns should be placed after liquefaction, but before subcooling of the CO₂ rich stream. Since the CO₂ is liquefied at three different pressure levels, either three columns must be used, or alternatively the column can be placed at the intermediate pressure (25 bar) or high pressure (65 bar). This will result in increased power requirements as more of the CO₂ must be compressed to a higher pressure. Also the irreversibilities in HX-101 will increase as there will be a larger temperature gap between the hot and cold composite curve. After removal of the volatiles the CO₂ should be subcooled in HX-101 to avoid flashing of gas in VD-101. The exact configuration of the volatile removal process can be determined on a case by case basis.

The processes are based on state-of-the-art process equipment. Plate-fin heat exchangers are selected for the main heat exchangers as they should be as compact as possible. For simplicity, only two heat exchangers are shown in the process flow diagram, however, it may be favourable to divide the heat exchangers into three or four sections, to decrease the complexity. All the process streams entering the heat exchangers are in single phase; hence, mal-distribution due to two-phase flow in the manifold system, which is a well-known problem in plate-fin heat exchangers in the LNG industry, is avoided. The heat transfer coefficients will be lower than for state-of-the-art LNG processes where the cooling duty required to condense the LNG is provided by vaporization of a mixed refrigerant. Plate-fin heat exchangers are well suited for the purpose, and are currently used for pressures up to 95 bar. Heatric exchangers can also be used. Standard centrifugal compressors are selected for the compressors. The cryogenic pumps are similar to the pumps used in LNG receiving terminals.

In the simple Liquefied Energy Chain (transport only), as shown in the inner part of FIG. 2, natural gas at 70 bar is processed and transported from the field site to the market site where it is delivered at 25 bar. CO₂ at atmospheric pressure is processed and transported from the market site to the field site where it is unloaded at 150 bar and a temperature of 15° C. LIN is used as a cold carrier and is emitted to the atmosphere in. The exergy conversion efficiency for the simple Liquefied Energy Chain is found in FIG. 20.

Nitrogen enters and leaves the system boundaries at ambient temperature and pressure and is therefore excluded from the calculations. The exergy efficiency for the process is 52% and the required energy is 319 kWh/tonne LNG. Production of nitrogen in an ASU will require 47 kWh/tonne nitrogen, which corresponds to 45 kWh/tonne LNG and will decrease the efficiency to 48%.

The ship utilization and the exergy efficiencies for the offshore, onshore and total process will vary with transport pressure of LNG and LIN. FIG. 18 shows the ship utilization (first axis) and the required amount of LCO₂ and LIN in the offshore process (second axis), as a function of LNG pressure and maximum ship pressure. On a similar basis, FIG. 19 shows the exergy efficiencies for the offshore, onshore and simple chain, versus LNG and maximum ship pressure.

The energy requirements, the required gas for fuel and the total irreversibilities for the simple energy chain are compared with a conventional LNG chain without Carbon Capture and Storage (CCS), which is chain A, a conventional LNG chain with CCS (B) and pipeline transport of natural gas with CCS where the CO₂ also is returned in a pipeline (C). The main results are presented in Table 5.

TABLE 5 Comparison of the efficiency of a conventional and the simple energy chain Energy Loss of req. NG due to [kWh/tonne Power power gen. LNG] cycle [%] Returned CO₂ 100% 80% Eff., [%] 100% 80% The Simple Offshore LEC 0 0 30 0 0 LEC Onshore LEC 338 319 50 4.5 4.2 ASU-nitrogen 45 45 50 0.6 0.6 Total 383 364 5.1 4.8 Chain A LNG 400 400 30 8.9 8.9 Conventional production LNG LNG receiv. 20 20 56.7 0.2 0.2 Total 420 420 9.1 9.1 Chain B LNG prod. 400 400 30 8.9 8.9 Conventional LNG receiv. 20 20 50 0.2 0.2 LNG with CO₂ LCO₂ prod. 300 240 50 4.0 3.2 transport LCO₂ regas. 18 14 30 0.4 0.5 Total 738 674 13.5 12.8 Chain C NG compr. 51 51 30 1.1 1.1 Pipeline CO₂ compr. 295 236 50 4.6 4.0 transport Total 346 287 5.7 5.1

As can be seen from Table 5 the LEC requires the same power as for pipeline transport (chain C) of NG and CO₂. However, for long distances ship transport (and the LEC) will be more effective than pipeline transport as recompression is needed due to the frictional drop in the pipeline. When comparing transport chains for stranded natural gas, it is seen that the LEC requires less than half of the total energy needed for ship transport of NG and CO₂ (chain B). The LEC energy requirement is, in fact, less than ship transport of natural gas without CO₂ capture (chain A).

The required power will be generated by conversion of natural gas to power. The efficiency for power generation in an open cycle offshore is 30%, whereas an onshore power plant with CO₂ recovery has an efficiency of 50% and a combined cycle power plant without CO₂ capture has an efficiency of 56.7%. The total exergy (thermo-mechanical and chemical) for the natural gas is 14413 kWh/tonne. Assuming the efficiencies given above, the loss of natural gas is 4.8 for the LEC, roughly the same as for pipeline transport, 5.1%. The LNG chains without (A) and with (B) CO₂ capture has two and three times as large NG losses with 9.1% and 12.8% respectively. Moreover, all the power required in the LEC is taken from a power plant with CO₂ capture, which means that most of the CO₂ will be captured. All other concepts will emit CO₂ to the atmosphere

The full LEC includes a power process with CO₂ capture. Oxyfuel concepts are especially suited as they will produce nitrogen as a by-product. Hence, the requirements for the production of nitrogen (45 kWh/tonne LNG) is avoided, as the required amount of nitrogen is far less than what corresponds to the amount of oxygen needed in an oxyfuel power plant. In the LEC, natural gas at 70 bar is processed and transported from the field site to the market site where it is used for electricity production in an oxyfuel power plant. An LHV efficiency of 50% (which corresponds to an exergy efficiency of 48%) is used in the calculations. The CO₂ is conditioned and transported to the field site where it is unloaded at 150 bar. The exergy efficiency for the full LEC is found in FIG. 21.

In the calculations a capture rate of 100% is used, although only 80% of the CO₂ is needed. This has minor implications on the process efficiencies; however, the ship utilization is reduced from 84% to 80%. The LEC chain is compared with a full conventional chain with and without CO₂ capture. The full LEC efficiency is the same as for pipeline transport, 46.6%, where as a similar conventional chain including production transport of LNG and CO₂ and a power plant with CO₂ capture will have an efficiency of 42.9%. The conventional utilization of natural gas with LNG production and transport and a CC power plant without a capture process will have an efficiency of 50.4%. 

1. A method of liquefaction of natural gas supplied by a field site, the method comprising the steps of: providing supplies of liquid nitrogen and liquid carbon dioxide, and performing a heat exchange process between the liquid nitrogen and the liquid carbon dioxide and the natural gas to thereby liquefy the natural gas, wherein the heat exchange process is arranged so that the resultant carbon dioxide is in gaseous or supercritical form at a pressure suited for injection for enhanced oil recovery.
 2. A method as claimed in claim 1, wherein no power input is required in the heat exchange process.
 3. A method as claimed in claim 1, wherein after the heat exchange process the nitrogen is in gaseous form and is vented to atmosphere.
 4. A method as claimed in claim 1, wherein the two phase region is avoided in at least one of the nitrogen, carbon dioxide and natural gas paths in the heat exchange process.
 5. A method as claimed in claim 1, wherein a combined carrier is provided, which initially contains the liquid nitrogen and the liquid carbon dioxide, and the method includes loading the liquefied natural gas onto the combined carrier.
 6. A method as claimed in claim 5, wherein the liquefied natural gas is stored in the same storage vessels on the combined carrier as the liquid nitrogen and the liquid carbon dioxide.
 7. A method as claimed in claim 5, wherein the heat exchange process is carried out on the combined carrier.
 8. A method as claimed in claim 1, further comprising the step of using the resultant carbon dioxide for enhanced oil recovery.
 9. A method as claimed in claim 1, further comprising the step of sequestration of the resultant carbon dioxide for final storage.
 10. An apparatus for liquefaction of natural gas, the apparatus being arranged to receive liquid nitrogen, liquid carbon dioxide and natural gas, wherein the apparatus comprises: a heat exchange device for transferring heat between the natural gas and the liquid nitrogen and the liquid carbon dioxide to thereby liquefy the natural gas, and wherein the heat exchange device is arranged such that the resultant carbon dioxide is in gaseous or supercritical form at a pressure suited for injection for enhanced oil recovery.
 11. An apparatus as claimed in claim 10, wherein the heat exchange device is arranged such that no power input is required.
 12. An apparatus as claimed in claim 10, wherein the heat exchange device is arranged such that the resultant nitrogen is in gaseous form and the apparatus includes means for venting the nitrogen gas to atmosphere.
 13. An apparatus as claimed in claim 10, wherein the heat exchange device is arranged such that the two phase region is avoided in at least one and preferably all of the nitrogen, carbon dioxide and natural gas paths.
 14. An apparatus as claimed in claim 10, comprising a combined carrier for containing and transporting the liquid nitrogen and the liquid carbon dioxide for input to the heat exchange device, and for containing and transporting the liquefied natural gas produced by the heat exchange device.
 15. An apparatus as claimed in claim 14, wherein the combined carrier comprises storage vessel for containing the liquefied natural gas or the liquid nitrogen and the liquid carbon dioxide.
 16. An apparatus as claimed in claim 14, wherein the heat exchange device is on the combined carrier.
 17. A method of producing natural gas, liquefied carbon dioxide and liquefied nitrogen comprising: providing amounts of liquefied natural gas, gaseous carbon dioxide and gaseous nitrogen, and transferring heat from the carbon dioxide and nitrogen to the liquefied natural gas in order to gasify the natural gas and liquefy the carbon dioxide and nitrogen.
 18. A method as claimed in claim 17, wherein the carbon dioxide is initially at atmospheric pressure and is compressed to a pressure higher than its triple point before it is liquefied.
 19. A method as claimed in claim 17, wherein the output natural gas is at above atmospheric pressure.
 20. A method as claimed in claim 17, wherein the liquid natural gas is compressed to a higher pressure than the output pressure of the gasified natural gas before being heated by heat exchange with the carbon dioxide and nitrogen, expanded to the output pressure to produce additional cold duty and work, and then further heated by carbon dioxide and nitrogen.
 21. A method as claimed in claim 17, wherein the nitrogen process includes compression followed by cooling by heat exchange with the natural gas to produce liquid nitrogen or cold dense phase nitrogen.
 22. A method as claimed in claim 17, wherein a valve or expander is used to reduce the pressure of the liquid or cold dense phase nitrogen to a pressure suitable for transport.
 23. A method as claimed in claim 17, wherein liquefaction of the carbon dioxide is achieved by splitting of the stream and compressing the split portions of the carbon dioxide to different pressure levels followed by heat exchange with the natural gas.
 24. A method as claimed in claim 17, wherein an air separation unit produces the nitrogen to be liquefied.
 25. A method as claimed in claim 24, wherein oxygen produced by the air separation unit is used for an Oxyfuel Power Plant.
 26. An apparatus comprising a heat exchanger, the apparatus arranged to receive liquefied natural gas, gaseous carbon dioxide and gaseous nitrogen and to produce liquid carbon dioxide and liquid nitrogen by gasification of the liquefied natural gas and transfer of heat from the carbon dioxide and nitrogen to the liquefied natural gas.
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